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Antero Resources Reports Fourth Quarter and Full Year 2019 Results and Announces 2020 Guidance and Proved Reserves

DENVER , Feb. 12, 2020 /PRNewswire/ --  Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced its fourth quarter and full year 2019 financial and operational results as well as its 2020 capital budget, guidance and proved reserves as of December 31 , 2019.  The relevant consolidated financial statements are included in Antero Resource's Annual Report on Form 10-K for the year ended December 31, 2019 .

Antero Resources logo. (PRNewsFoto/Antero Resources Corporation)

Fourth Quarter and Full Year 2019 Highlights Include:

  • Net production averaged 3,185 MMcfe/d (30% liquids by volume) during the fourth quarter and 3,220 MMcfe/d for the full year, a 19% year-over-year increase compared to 2018
  • Realized natural gas equivalent price averaged $3.18 per Mcfe during the quarter
  • All-in cash expenses were $2.34 per Mcfe during the quarter, a $0.22 , or 8% reduction from the first half of 2019
  • Drilling and completion capital spending was $300 million during the fourth quarter and $1.27 billion for the full year, an 11% and 14% decrease, respectively, compared to the prior year periods
  • Proved reserves increased 5% to 18.9 Tcfe at year-end 2019 compared to year-end 2018 and proved developed reserves increased 13% to 11.7 Tcfe
  • Future development cost estimate for 7.2 Tcfe of proved undeveloped reserves is $0.37 per Mcfe

2020 Guidance Highlights:                                                                                                

  • Drilling and completion capital budget of $1.15 billion , down 10% from 2019
  • Full year 2020 net production is expected to average 3,500 MMcfe/d, a 9% increase over 2019 net production
  • All-in cash expenses, including net marketing expense, are expected to be $2.25 to $2.35 per Mcfe, an $0.18 decrease from 2019
  • Natural gas production guidance is 94% hedged at $2.87 /MMBtu
  • Estimated oil and oil-equivalent production of 26,000 Bbl/d (pentanes are hedged to WTI) is 100% hedged in 2020 at $55.63 /Bbl

Paul Rady , Chairman and Chief Executive Officer of Antero Resources commented, "Our 2020 capital budget highlights the direct benefit from our well cost savings initiatives that we launched in 2019.  In simple terms, we have reduced our total well cost per foot from $970 in the initial 2019 budget to a target of $795 to $825 per for 2020.  The result is a 10% reduction in drilling and completion capital and a 28% reduction in lease operating expense as compared to 2019, while delivering production growth of 9%.  This level of production in turn should trigger $75 million in previously announced gathering, processing and transportation expense savings in 2020 and paves the way for up to $350 million in total savings between 2020 and 2023.  Additionally, by growing into our unutilized firm transportation commitments we reduce our cost structure by another $200 million by 2022."

Mr. Rady continued, "We believe that our industry-leading hedge portfolio and diversified production mix, combined with our ability to export more than 50% of our C3+ NGL production to premium international markets, provides Antero with a competitive advantage throughout commodity price cycles.  Our cost savings initiatives and liquids exposure result in a projected cash flow neutral profile for 2020 at current strip pricing including the $125 million water earnout payment received in January from Antero Midstream."

2020 Capital Budget and Guidance

The following is a summary of Antero Resources' 2020 capital budget.  The capital budget is based on commodity strip pricing as of February 7, 2020 that was $52 per barrel WTI oil, $25 per barrel C3+ NGL and $2.08 per MMBtu NYMEX natural gas for 2020. 

Capital Budget ($ in Billions)






Drilling & Completion



$1.15


Land



$0.05


    Total E&P Capital



$1.2


The following is a summary of Antero Resources' 2020 production, pricing and cash expense guidance.

Production Guidance 





Net Daily Natural Gas Equivalent Production (MMcfe/d)



3,500

Net Daily Natural Gas Production (MMcf/d)



2,375

Total Net Daily Liquids Production (Bbl/d): 



187,500




Realized Pricing Guidance





Natural Gas Realized Price vs. NYMEX Henry Hub ($/Mcf)


$0.00 $0.10

Oil Realized Price vs. WTI Oil ($/Bbl)


($7.00) ($9.00)

C3+ NGL Realized Price vs. Mont Belvieu ($/Gal)


$0.00 $0.05





Cash Expense Guidance



Low


High

Cash Production Expense ($/Mcfe) (1)



$2.07


$2.13

Marketing Expense, Net of Marketing Revenue ($/Mcfe)



$0.10


$0.12

G&A Expense ($/Mcfe) (2)



$0.08


$0.10

All-In Cash Expense



$2.25


$2.35


(1)

Includes lease operating expenses, gathering, compression, processing and transportation expenses ("GP&T") and production and ad valorem taxes.

(2)

Excludes equity-based compensation.

Well Cost Savings

Antero's drilling and completion capital budget is based on average total well cost of $825 per foot, which is at the high end of the 2020 target range of $795 to $825 per foot.  Well costs averaged $860 per foot in the fourth quarter of 2019 with only a portion of the wells being completed with reduced water.  The reduction in 2020 well costs is expected to be driven by both drier completions (36 Bbl of water per foot of lateral) on all wells and expanded produced water services provided by Antero Midstream. 

Fourth Quarter 2019 Financial Results

For the three months ended December 31, 2019 , Antero reported a GAAP net loss of $482 million , or $1.61 per diluted share, compared to a GAAP net loss of $122 million , or $0.39 per diluted share, in the prior year period.  Adjusted Net Loss (non-GAAP measure) was $6 million , or $0.02 per diluted share, compared to Adjusted Net Income of $175 million during the three months ended December 31, 2018, or $0.56 per diluted share.  The Adjusted Net Loss reflects a $468 million impairment based on the fair value of our equity interest in Antero Midstream at year end 2019.

Adjusted EBITDAX (non-GAAP measure) was $295 million , a 38% decrease compared to $475 million in the prior year period due to lower commodity pricing.  Antero's average realized price after hedges declined 20% from $3.97 per Mcfe in the fourth quarter of 2018 to $3.18 per Mcfe in the fourth quarter of 2019.

The following table details the components of average net production and average realized prices for the three months ended December 31, 2019 :



Three months ended December 31, 2019



Natural Gas
(MMcf/d)


Oil (Bbl/d)


C3+ NGLs
(Bbl/d)


Ethane
(Bbl/d)


Combined
Natural Gas
Equivalent
(MMcfe/d)

Average Net Production



2,223



8,793



104,376



47,014



3,185

















Average Realized Prices


Natural Gas
($/Mcf)


Oil ($/Bbl)


C3+ NGLs
($/Bbl)


Ethane
($/Bbl)


Combined
Natural Gas
Equivalent
($/Mcfe)

Average realized prices before settled derivatives


$

2.50


$

49.29


$

29.61


$

7.44


$

2.96

Settled commodity derivatives



0.37



4.28



(1.66)





0.22

Average realized prices after settled derivatives


$

2.87


$

53.57


$

27.95


$

7.44


$

3.18

















NYMEX average price


$

2.50


$

56.96








$

2.50

Premium / (Differential) to NYMEX


$

0.37


$

(3.39)








$

0.68

Net daily natural gas equivalent production in the fourth quarter averaged 3,185 MMcfe/d, including 160,183 Bbl/d of liquids (30% liquids by volume).  Liquids revenue represented approximately 41% of total product revenue before hedges.  Production declined 1% from the prior year period due to the timing of well completions in 2019 as two pads, totaling 13 wells, were turned to sales in late December of 2019. 

Antero's average realized C3+ NGL price before hedging was $29.61 per barrel, representing a 4% decrease versus the prior year period and a 31% increase from the third quarter of 2019.  Antero shipped 41% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.21 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA.  Antero sold the remaining 59% of C3+ NGL net production at a $0.09 per gallon discount to Mont Belvieu pricing at Hopedale, OH.  The resulting blended price on 104,376 Bbl/d of net C3+ NGL production was $29.61 per barrel, which was a $0.03 per gallon premium to Mont Belvieu pricing.  Based on current strip prices at Mont Belvieu and in the international markets, Antero expects its realized C3+ NGL prices in 2020 to be $0.00 to a $0.05 per gallon premium to Mont Belvieu.  Antero expects to sell at least 50% of its C3+ NGL production in 2020 at Marcus Hook for export at a premium to Mont Belvieu.    


Three months ended December 31, 2019



Pricing Point


Net C3+ NGL

Production
(Bbl/d)


% by
Destination


Premium (Discount)

To Mont Belvieu
($/Gal)

Propane / Butane shipped on ME2

Marcus Hook


42,794


41%


$0.21

Remaining C3+ NGL volume

Hopedale


61,582


59%


($0.09)

Total C3+ NGLs




104,376


100%


$0.03

Cash Expense and Net Marketing Expense

All-in per unit cash expense, which includes lease operating, GP&T, production and ad valorem taxes, net marketing and general and administrative expense (excluding equity-based compensation) was $2.34 per Mcfe in the fourth quarter, an 8% decrease compared to $2.56 per Mcfe average during the first half of 2019.  Antero expects all-in cash expense of $2.25 to $2.35 per Mcfe as a result of the recently announced midstream fee reductions, filling unutilized firm transportation, and ongoing progress on the water savings initiatives that reduces lease operating expense.  

Per unit net marketing expense declined to $0.17 per Mcfe in the fourth quarter compared to $0.22 per Mcfe reported in the prior year period.  The decline was driven by the mitigation of some of our excess firm transportation expense.  Net marketing expense is expected to decline further in 2020, to $0.10 to $0.12 per Mcfe, as a result of both an increase in natural gas production filling excess firm transportation capacity and renegotiated agreements with midstream providers that allow for higher utilization of our transportation capacity to the more attractive pricing in the Gulf Coast markets. 

Adjusted EBITDAX margin (non-GAAP measure) was $1.01 per Mcfe, a 37% decrease from the prior year period, due to lower realized prices relative to the prior year period.  The following table presents a calculation of Adjusted EBITDAX margin on a per Mcfe basis and a reconciliation to the realized price before cash receipts for settled derivatives, the nearest GAAP financial measure.  Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, and is a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations on a per unit basis from period to period by removing the effect of its capital structure from its operating structure.











Three months ended December 31,




2018


2019


Adjusted EBITDAX margin ($ per Mcfe):








Realized price before cash receipts for settled derivatives


$

4.05


$

2.96


Distributions/dividends from Antero Midstream



0.16



0.17


Marketing, net



(0.22)



(0.17)


Gathering, compression, processing and transportation costs



(1.88)



(1.88)


Lease operating expense



(0.15)



(0.09)


Production and ad valorem taxes



(0.15)



(0.10)


General and administrative (excluding equity-based compensation)



(0.11)



(0.10)


Adjusted EBITDAX margin before settled commodity derivatives



1.70



0.79


Cash receipts for settled commodity derivatives



(0.09)



0.22


Adjusted EBITDAX margin ($ per Mcfe):


$

1.61


$

1.01


Fourth Quarter 2019 Operating Update

Marcellus Shale Antero placed 21 horizontal Marcellus wells to sales during the fourth quarter of 2019 with an average lateral length of 11,600 feet.  For new wells that had 60 days of reported production data during the quarter, the average 60-day rate per well was 18.2 MMcfe/d on choke. The 60-day average rate per well included 742 Bbl/d of liquids, comprised of oil, C3+ NGLs and assumes 25% ethane recovery. 

Additionally, Antero drilled an average of 7,000 lateral feet per day in the quarter, achieving its highest quarterly rate in the Company's history.  This drilling record represents a 17% sequential increase and a 38% increase compared to the 2018 average in lateral footage performance.  Antero also drilled a company one-well record of 10,453 lateral feet in a 24-hour period.  During 2019, Antero drilled 97 wells that averaged over one mile per day drilling in the lateral and was the only known operator in the Marcellus to drill over 10,000 lateral feet in a 24-hour period, which Antero accomplished twice.  Antero's ongoing emphasis on completion efficiencies resulted in an improvement during the fourth quarter, as the Company averaged 6.3 stages completed per day, representing a 7% increase from 5.9 stages per day in the prior period.    

Fourth Quarter and Full Year 2019 Capital Investment

Antero's accrued drilling and completion capital expenditures for the three months ended December 31, 2019 were $300 million .  For the full year 2019, drilling and completion capital expenditures were $1.27 billion , a decrease of 16% from 2018 and 7% below Antero's original 2019 guidance. 

Balance Sheet and Liquidity

As of December 31, 2019 , Antero's total debt was $3.76 billion , of which $552 million were borrowings outstanding under the Company's revolving credit facility.  Antero has a borrowing base of $4.5 billion with lender commitments that total $2.64 billion .  After deducting letters of credit outstanding of $623 million , the Company had $1.5 billion in available liquidity.  The decrease in Antero's outstanding letters of credit from the prior period reflect new surety bonds that were secured during the fourth quarter.  As of December 31, 2019 , Antero's net debt to trailing twelve months Adjusted EBITDAX ratio was 3.0x.

Antero repurchased $225 million principal amount of senior unsecured notes during the fourth quarter at a 17% weighted average discount price, including both its 2021 and 2022 senior notes.  The repurchases reduced Antero's total debt by $37 million and net interest expense was reduced by $6 million on an annualized basis. Antero also repurchased 8.3 million shares of common stock during the fourth quarter at a weighted average price of $2.50 per share. 

President and CFO, Glen Warren , commented, "Our ability to materially reduce operating costs and lower capital spending allows us to protect our balance sheet while executing a moderate near-term growth strategy to fill our remaining unfilled premium firm transportation and realize the midstream fee reductions announced in December.  Pro forma for the recently announced asset sale program, we are targeting a mid 2-times leverage ratio with robust liquidity of $2.3 billion at year-end 2020 excluding further senior note repurchases or redemptions.  Longer term, we are committed to reducing absolute debt and maximizing free cash flow as we expect to fill our premium firm transportation commitments by the end of 2021."    

Year End Proved Reserves

At December 31, 2019 , Antero's estimated proved reserves were 18.9 Tcfe, a 5% increase over the prior year.  Estimated proved reserves were comprised of 61% natural gas, 38% NGLs and 1% oil.  The Marcellus Shale accounted for 92% of estimated proved reserves and the Ohio Utica Shale accounted for 8%.  For 2019, Antero added 3.7 Tcfe of estimated proved reserves.  Approximately 2.3 Tcfe was removed from Antero's proved reserves due to the SEC 5-year rule, primarily related to changes in drilling locations in our 5-year development plan.

Estimated proved developed reserves were 11.7 Tcfe, a 13% increase over the prior year.  The percentage of estimated proved reserves classified as proved developed increased to 62% at year-end 2019, compared to 58% at year-end 2018.  Antero's 328 proved undeveloped locations average an estimated 1258 BTU, with an average lateral length of approximately 12,500 feet.

Antero's 7.2 Tcfe of estimated proved undeveloped reserves will require an estimated $2.6 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe. 

The following table presents a summary of changes in estimated proved reserves (in Tcfe).

Proved reserves, December 31, 201 8


18.0

Extensions, discoveries, and other additions


3.7

Revisions to prior estimates


(1.6)

Estimated Production


(1.2)

Proved reserves, December 31, 201 9


18.9

The following table summarizes pre-tax estimated proved reserves PV-10 (non-GAAP measure) and the associated Standardized Measure.  The decrease in pre-tax estimated proved reserves PV-10 value as compared to 2018, was due primarily to lower SEC pricing and the deconsolidation of Antero Resources' and Antero Midstream's financial statements.  Lower pricing resulted in approximately 65% of the decline and the deconsolidation resulted in approximately 35% of the reduction.  The deconsolidation resulted in Antero Resources recording the full fees paid to Antero Midstream for services rendered and no longer recording the future capital expenditures associated with Antero Midstream assets in future development costs. Prior to deconsolidation, as required by SEC guidance, Antero Resources' consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream and the inclusion of the operating costs and capital incurred by Antero Midstream.  Detailed SEC pricing can be found in Antero's Form 10-K for the year ended December 31, 2019 .










SEC Pricing





Proved Reserve Value ($B):

2019  

Year-End


2018  

Year-End




%


(Deconsolidated)


(Consolidated)


Variance


Variance

Standardized Measure

$5.5


$10.5


$5.0


-52%

Pre-tax estimated proved reserves PV-10

$6.1


$12.6


$6.5


-52%

Pre-tax estimated proved developed reserves PV-10

$4.7


$8.4


$3.7


-45%

Commodity Derivative Positions

Antero has hedged 1.8 Tcf of natural gas at a weighted average index price of $2.84 per MMBtu through 2023 with fixed price swap positions.  Antero also has oil and NGL fixed price swap positions, including NGL positions that totaled 35,800 Bbl/day and oil positions that totaled 10,000 Bbl/d during 2020.  As of December 31, 2019 , the Company's estimated fair value of commodity derivative instruments was $1.1 billion based on strip pricing.

Please see Antero's Annual Report on Form 10-K for the year ended December 31, 2019, for more information on all commodity derivative positions. 

The following tables summarize Antero's hedge position as of December 31, 2019 :

Fixed price natural gas positions from January 1, 2020 through December 31, 2023 were as follows:



Natural gas

MMBtu/day


Weighted

average index

price

Year ending December 31, 2020:






NYMEX ($/MMBtu)


2,227,500


$

2.87

Year ending December 31, 2021:






NYMEX ($/MMBtu)


2,400,000


$

2.80

Year ending December 31, 2022:






NYMEX ($/MMBtu)


0


$

N/A

Year ending December 31, 2023:






NYMEX ($/MMBtu)


90,000


$

2.91

C3+ NGL and Oil derivative contract positions from January 1, 2020 through December 31, 2020 were as follows:


Derivative
Contract
Type

Liquids Hedges
(Bbl/d)


Weighted
average
index price
($/Gal)

Weighted
average basis

differential
$/Gal

Weighted
average index
price ($/Bbl)

Year ending December 31, 2020:







Propane (C3) Mont Belvieu (Domestic)

Fixed swap

373


$0.50


$21.00

Propane (C3) ARA (Europe) (1)

Fixed swap

10,371


$0.55


$23.10

Propane (C3) FEI (Asia) (1)

Fixed swap

2,457


$0.61


$25.62

Normal Butane (C4) ARA to Mont Belvieu Basis

Basis

1,072


$0.23

Normal Butane (C4) Mont Belvieu (Domestic)

Fixed swap

1,492


$0.57


$24.12

Pentane (C5) Mont Belvieu (Domestic) (2)

Fixed swap

20,000


$1.06


$44.52

Total C3+ NGLs


35,765












Total NYMEX Crude Oil


10,00...